Automatic mud pulse telemetry band selection

ABSTRACT

A method for automatically selecting a frequency band for transmission of a mud pulse telemetry signal includes transforming acquired transducer measurements from a time domain to a frequency domain to obtain a spectrum of measurements. The spectrum of measurements is processed to compute a total energy in band and a standard deviation of the power spectral density in band for a plurality of frequency bands. A ratio of the total energy in band to the standard deviation acquiring a plurality of transducer measurements of transmitted mud pulse telemetry pressure pulses and of the power spectral density in band is computed for at least two of the plurality of frequency bands. The frequency band having the highest computed ratio is selected and automatically downlinked to a downhole mud pulse telemetry transmitter.

RELATED APPLICATIONS

This application claims the benefit of and priority to U.S. ProvisionalPatent Application No. 62/120,303, filed on Feb. 24, 2015, the entiredisclosure of which is incorporated herein by reference.

FIELD

The disclosed embodiments relate generally to downhole communicationmethods in subterranean drilling operations and in particular to amethod for automatically selecting a mud pulse telemetry frequency band.

BACKGROUND

Typical petroleum drilling operations employ a number of techniques togather information about the wellbore and the formation through which itis drilled. Such techniques are commonly referred to in the art asmeasurement while drilling (MWD) and logging while drilling (LWD). MWDand LWD techniques may be used, for example, to obtain information aboutthe well (e.g., information about the size, shape, and directionthereof) and the properties of the surrounding formation (e.g., thedensity, porosity, and resistivity thereof which may be related to thehydrocarbon bearing potential).

Transmission of data from a downhole tool in the drill string to thesurface is a difficulty common to many MWD and LWD operations. Mud pulsetelemetry techniques may be utilized for such data transmission. In mudpulse telemetry operations, data may be encoded as a series of pressurepulses that are transmitted through the column of drilling fluid to thesurface. These pressure pulses are measured at the surface where theymay be decoded to provide the transmitted data to the drilling operator.

Mud pulse telemetry signals are well known to be highly noisy andattenuated such that the resulting data transmission rate is generallyvery slow (e.g., on the order of about 1 to about 10 bits per second oreven less). The noise and attenuation commonly depend on many factorsincluding the wellbore depth, drilling fluid properties, the physicalstructure of the drill string, and the frequency of the transmittedsignal. Signal noise and attenuation can vary widely during a drillingoperation such that there is a need for improved telemetry methods thatautomatically select the frequency band of the mud pulse telemetrychannel.

SUMMARY

A method for automatically selecting a frequency band for transmissionof a mud pulse telemetry signal is disclosed. The method includesacquiring a plurality of transducer measurements of transmitted mudpulse telemetry pressure pulses and transforming the acquired transducermeasurements from a time domain to a frequency domain to obtain aspectrum of measurements. The spectrum of measurements is processed tocompute a total energy in band and a standard deviation of the powerspectral density in band for a plurality of frequency bands. A ratio ofthe total energy in band to the standard deviation of the power spectraldensity in band is computed for at least two of the plurality offrequency bands. The frequency band having the highest computed ratio isselected and automatically downlinked to a downhole mud pulse telemetrytransmitter.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the disclosed embodiments, andadvantages thereof, reference is now made to the following descriptionstaken in conjunction with the accompanying drawings, in which:

FIG. 1 depicts a drilling rig on which the disclosed method embodimentsmay be utilized.

FIG. 2 depicts a mud flow arrangement in which the disclosed methods maybe utilized.

FIG. 3 depicts a flowchart of one disclosed method embodiment.

FIG. 4 depicts a plot of magnitude versus frequency (a spectrum) of areceived pressure signal.

FIG. 5 depicts a block diagram of a disclosed method embodiment.

FIGS. 6 and 7 depict various spectra that show incidents of rotarynoise, drilling noise, pump noise and mud motor stalls.

DETAILED DESCRIPTION

FIG. 1 depicts one example of an offshore drilling assembly, generallydenoted 10, suitable for employing the disclosed method embodiments. InFIG. 1 a semisubmersible drilling platform 12 is positioned over an oilor gas formation (not shown) disposed below the sea floor 16. A subseaconduit 18 extends from deck 20 of platform 12 to a wellheadinstallation 22. The platform may include a derrick and a hoistingapparatus for raising and lowering the drill string 30, which, as shown,extends into borehole 40 and includes drill bit 32, a transmissiondevice 50 (e.g., a electromechanical pulser or a mud siren), and atleast one MWD and/or LWD tool 60. Drill string 30 may optionally furtherinclude substantially any number of other downhole tools including, forexample, other MWD and/or LWD tools, stabilizers, a rotary steerabletool, a reamer, and a downhole drilling motor. The disclosed embodimentsare not limited in this regard.

It will be understood that the MWD and/or LWD tool 60 may includesubstantially any suitable downhole measurement sensors. An MWD toolcommonly includes survey sensors such as accelerometers, magnetometers,and/or gyroscopic sensors for measuring the orientation of the wellborewith respect to a fixed reference such as the Earth's gravitational andmagnetic fields. LWD tools commonly include one or more formationevaluation sensors, such as internal or annular pressure sensors,temperature sensors, natural gamma ray sensors, neutron sensors, densitysensors, electromagnetic antennas, resistivity sensors, ultrasonicsensors, audio-frequency acoustic sensors, and the like. The disclosedembodiments are not limited in this regard.

It will further be understood that the deployment illustrated on FIG. 1is merely an example and that the disclosed embodiments are not limitedto use with a semisubmersible platform 12 as depicted. The disclosedembodiments are equally well suited for use with any kind ofsubterranean drilling operation, either offshore or onshore.

Referring now to FIG. 2, one example of a drilling fluid system 80employed in a downhole drilling system is illustrated. During a drillingoperation, drilling fluid (commonly referred to as “mud” in the art) ispumped downward through the drill string and the bottom hole assembly(BHA) where it emerges at or near the drill bit at the bottom of thewellbore. The mud serves several purposes, including cooling andlubricating the drill bit, clearing cuttings away from the drill bit andtransporting them to the surface, and stabilizing and sealing theformation(s) through which the borehole traverses.

In the depicted drilling fluid system 80, a mud pump 81 generates adownward traveling flow 83 of drilling fluid (mud) into a standpipe 95and down through the drill string 30. Rotation of the drill string(and/or drill bit 32) cuts the formation and creates the wellbore 40 inthe earth (or in sea floor 16 as shown on FIG. 1). The mud flow 83emerges at or near the drill bit 32 and creates an upwardly travelingmud flow 84 through annulus 46 (the space between the drill string 30and the borehole wall). The drilling fluid system 80 may further includea pulsation dampener 90 (also referred to in the art as a desurger) thatevens out the flow 83 in the standpipe 95 and the drill string 30. Thepulsation dampener 90 essentially acts like an accumulator to smoothoutlet pressure generated by the mud pump 81.

MWD and/or LWD data is encoded downhole (e.g., via a conventionaldownhole controller). A transmission device 50, such as a conventionalelectromechanical mud pulser or a mud siren, produces an acousticpressure wave 85 (e.g., including a plurality of pressure pulses whichencode the data). Commonly assigned U.S. Pat. Nos. 5,073,877 and6,970,398, which are incorporated by reference in their entirety herein,disclose suitable mud pulse telemetry transmission devices. The pressurewave 85 travels towards the surface at approximately the speed of sound(e.g., in the range from about 2000 to about 4500 feet per second)through the downward traveling mud 83 in the drill string 30. It will beappreciated that the signal may also be transmitted through and receivedfrom the upward traveling mud flow 84 in the annulus 46 (although suchtransmission is uncommon). It will also be appreciated that thedisclosed embodiments are not limited to any particular pressure wave orpressure pulse configuration and that substantially any suitableencoding schemes may be utilized.

The transmitted pressure wave 85 may be received (detected) at one ormore sensors (e.g., transducers) 87 at the surface and processed asdescribed in more detail below. It will be understood that suchprocessing may employ substantially any suitable processing means 89(e.g., a computer or controller). Implicit in the control and processingof the received signals described herein is the use of a computerprogram (software or firmware) executed on a suitable computer platform(hardware) including, for example, a microprocessor and machine readableelectronic memory. The disclosed embodiments are, of course, not limitedto any particular controller/computer configuration. Substantially anysuitable transducer arrangement may also be utilized.

FIG. 3 depicts a flowchart of one disclosed method embodiment 100.Pressure pulses in the drilling fluid are received at one or moretransducers at 102 (e.g., at transducer 87 on FIG. 2). For example,transducer data may be continuously acquired over a short time window(e.g., in a range from about 10 to about 100 seconds or more). Thetransducer data is processed at 104 to compute a spectrum (i.e., totransform the transducer data from a time domain to a frequency domain).Such processing may employ, for example, a fast Fourier transform (FFT)or another suitable transform known to those of ordinary skill in theart. The spectrum may be further processed at 106 to compute the totalenergy in band and the standard deviation of the power spectral densityin band using small increments in frequency (and optionally bandwidth).The in band energy and the in band standard deviation may be computed,for example, using the following mathematical equations:

${E\left( {{fc},{BW}} \right)} = {\sum\limits_{k = {{fc} - \frac{BW}{2}}}^{{fc} + \frac{BW}{2}}{S(k)}^{2}}$and${{Sdev}\left( {{fc},{BW}} \right)} = \sqrt{\frac{1}{BW}{\sum\limits_{k = {{fc} - \frac{BW}{2}}}^{{fc} + \frac{BW}{2}}\left( {{{PSD}(k)} - \overset{\_}{{PSD}(k)}} \right)^{2}}}$

where E(fc, BW) represents the total energy in band, Sdev(fc, BW)represents the standard deviation of the power spectral density in band(also referred to as the standard deviation in band), fc represents thecenter frequency of the band, BW represents the bandwidth of the band,S(k) represents the magnitude of the spectrum at each incrementalfrequency, and PSD(k) represents the magnitude squared at eachincremental frequency.

It will be understood that the total energy in band and the standarddeviation of the power spectral density in band may be computed forsubstantially any plurality of frequency bands having substantially anysuitable bandwidth. Moreover, the frequency bands may be overlapping ornon-overlapping. In one example embodiment the total energy in band andthe standard deviation of the power spectral density in band may becomputed for 20 distinct non-overlapping frequency bands each of whichhas a bandwidth of 1 Hz. In other embodiments, the energy in band andthe standard deviation in band may be computed for 10 distinct frequencybands. In another embodiment, the energy in band and the standarddeviation in band may be computed only for selected bands at which theMWD tool is able to transmit (e.g., at 1, 2, 3, 4, and 5 Hz). Thedisclosed embodiments are of course not limited in this regard.

It will be further understood that the drilling fluid in the drillstring tends to function as a low pass filter such that higherfrequencies can be significantly attenuated (e.g., at frequenciesgreater than about 40 Hz (or about 20 Hz) depending on the length of thedrill string). Thus, in certain embodiments, the energy in band and thestandard deviation of the power spectral density in band need not becomputed at higher frequency bands.

With continued reference to the flow chart on FIG. 3, method 100 mayoptionally further include eliminating selected low energy bands at 108and weighting the energy in band by the center frequency of the band at110. While these steps are optional they may be beneficial in certainapplications. For example, destructive interference in the communicationchannel (the mud column) may result in very low signal energies atcertain frequencies. Moreover these frequencies at which destructiveinterference occur may not be constant. It may therefore be advantageousto identify and eliminate these frequency bands from furtherconsideration. For example, in certain embodiments, frequency bandshaving an energy in band value less than a predetermined threshold maybe eliminated at 108. It will be understood that substantially anysuitable threshold may be utilized. For example, the threshold may beobtained by multiplying the smallest computed total energy in band by afactor (such as 10).

As stated above, the drilling fluid in the drill string tends toattenuate higher frequency signals and function as a low pass filter. Itmay therefore be advantageous to compute a weighted energy in band at110 in which the received energies at higher frequencies are assignedhigher weights. For example, a linear weighting function may be used inwhich the energy in band is multiplied by the center frequency of theband. In an embodiment, the weighting function may include the inverseof a low pass filter (e.g., the weighting function may equal √{squareroot over (1+fc²)}, where fc is as defined above). The disclosedembodiments are not limited to the use of any particular weightingfunction. Nor are they limited to computing a weighted energy in band.

With further reference to FIG. 3, a ratio of the energy in band to thestandard deviation in band may be computed for each frequency band at112 (or for each frequency band that is not eliminated at 108). Inembodiments in which the energy in band is weighted at 110 a ratio ofthe weighted energy in band to the standard deviation in band may becomputed at 112. The frequency band having the highest ratio may then beselected at 114 as the optimum frequency band for mud pulse telemetry.Method 100 may then automatically trigger a surface controller todownlink the selected frequency band from the surface processor to thedownhole telemetry system at 116.

FIG. 4 depicts one example of a spectrum computed at 104 of method 100(shown on FIG. 3). The spectrum includes a plot of magnitude versusfrequency (in units of Hz) for transducer data acquired at a frequencyof 240 Hz during over a 30 second interval (for a total of 7200transducer measurements). An optimum band (e.g., selected at 114 of FIG.3) is depicted as being centered at about 3 Hz.

FIG. 5 depicts a block diagram of a disclosed method embodiment 200.Stand pipe transducer (pressure) measurements are acquired at 202 over awide frequency band (e.g., in a range from about 0 to about 240 Hz). Themeasurements are digitized at 204 and processed at 206. The processingmay include, for example, a pump stroke estimation at 208 with a flow incalculation at 210, a spectrogram display at 212, and an MWD signalstrength calculation at 214. The processed measurements may then beutilized in combination with other surface or downhole measurements 216to trigger various alarms and/or make drilling recommendations for thedrilling operator at 218.

The pump stroke estimation at 208 using the stand pipe transducermeasurements may advantageously obviate the need to install pump strokesensors in the mud pumps. The estimated pump strokes may then be used tofurther estimate the flow in of drilling fluid (e.g., the drilling fluidflow rate) based on an estimated mud volume per pump stroke. Furtherflow in information may be utilized various alarms (e.g., kick, washout,lost circulation, etc.).

The transducer measurements may be displayed at 212, for example, in thetime domain or the frequency domain. FIGS. 6 and 7 depict variousspectra that show incidents of rotary noise, drilling noise, pump noiseand mud motor stalls. Evaluation of these spectra may reveal changes inthe drilling environment and drilling activities over time. For example,evaluation of the noise signal may enable an optimum weight on bit (WOB)and drill string rotation rate (RPM) to be achieved while drilling.Based on the spectrum the drilling operator may manually adjust the WOBand RPM to achieve the desired drilling conditions (i.e., having thedesired noise signal in the spectrum). The spectrum may also indicateincidents of mud motor stalling which tend to result in noise spikes inthe spectrum. The drilling fluid flow rate and the WOB may be adjustedto minimize mud motor stalling incidents (based on the evaluation of thespectrum noise).

The mud pulse telemetry signal strength may also be evaluated at 214 toidentify incidents of wellbore washout. In general, a washout tends toreduce the MWD signal strength. A reduction in MWD signal strength maytherefore be indicative of wellbore washout.

An automatic method for selecting a mud pulse telemetry band and certainadvantages thereof have been described in detail, it should beunderstood that various changes, substitutions and alternations can bemade herein without departing from the spirit and scope of thedisclosure. Features shown in individual embodiments referred to abovemay be used together in combinations other than those which have beenshown and described specifically. Accordingly, all such modificationsare intended to be included within the scope of this disclosure. In theclaims, means-plus-function clauses are intended to cover the structuresdescribed herein as performing the recited function and not onlystructural equivalents, but also equivalent structures. Thus, although anail and a screw may not be structural equivalents in that a nailemploys a cylindrical surface to secure wooden parts together, whereas ascrew employs a helical surface, in the environment of fastening woodenparts, a nail and a screw may be equivalent structures. It is theexpress intention of the applicant not to invoke means-plus-function forany limitations of any of the claims herein, except for those in whichthe claim expressly uses the words ‘means for’ together with anassociated function.

I claim:
 1. A method for automatically selecting a frequency band fortransmission of a mud pulse telemetry signal, the method comprising: (a)acquiring a plurality of transducer measurements of transmitted mudpulse telemetry pressure pulses; (b) transforming the transducermeasurements acquired in (a) from a time domain to a frequency domain toobtain a spectrum of measurements; (c) processing the spectrum ofmeasurements to compute a total energy in band and a standard deviationof the power spectral density in band for a plurality of frequencybands; (d) computing a ratio of the total energy in band to the standarddeviation of the power spectral density in band for at least two of theplurality of frequency bands; (e) selecting the frequency band havingthe highest ratio computed in (d); and (f) automatically downlinking thefrequency band selected in (e) to a downhole mud pulse telemetrytransmitter.
 2. The method of claim 1 wherein the transducermeasurements are transformed in (b) using a fast Fourier transform. 3.The method of claim 1, wherein the total energy in band and the standarddeviation of the power spectral density in band are computed using thefollowing mathematical equations:${E\left( {{fc},{BW}} \right)} = {\sum\limits_{k = {{fc} - \frac{BW}{2}}}^{{fc} + \frac{BW}{2}}{S(k)}^{2}}$${{Sdev}\left( {{fc},{BW}} \right)} = \sqrt{\frac{1}{BW}{\sum\limits_{k = {{fc} - \frac{BW}{2}}}^{{fc} + \frac{BW}{2}}\left( {{{PSD}(k)} - \overset{\_}{{PSD}(k)}} \right)^{2}}}$wherein E(fc, BW) represents the total energy in band, Sdev(fc, BW)represents the standard deviation of the power spectral density in band,fc represents a center frequency of the frequency band, BW represents abandwidth of the frequency band, S(k) represents a magnitude of thespectrum at each incremental frequency, and PSD(k) represents amagnitude squared at each incremental frequency.
 4. The method of claim1, wherein (c) and (d) in combination comprise: (i) processing thespectrum of measurements to compute the total energy in band and thestandard deviation of the power spectral density in band for theplurality of frequency bands; (ii) discarding frequency bands in whichthe total energy in band is less than a threshold; and (iii) computing aratio of the total energy in band to the standard deviation of the powerspectral density in band for the frequency bands not discarded in (ii).5. The method of claim 4, wherein the threshold is ten times a smallestenergy in band computed (i).
 6. The method of claim 1, wherein (c) and(d) in combination comprise: (i) processing the spectrum of measurementsto compute the total energy in band and the standard deviation of thepower spectral density in band for the plurality of frequency bands;(ii) processing the total energy in band and a center frequency of thefrequency band to compute a weighted energy in band; and (iii) computinga ratio of the weighted energy in band to the standard deviation of thepower spectral density in band for the frequency bands not discarded in(ii).
 7. The method of claim 6, wherein the processing in (ii) assignsmore weight to the total energy in band in higher frequency bands. 8.The method of claim 6, wherein the total energy in band is weighted by afactor equal to: √{square root over (1+fc²)}, where fc represents thecenter frequency.
 9. The method of claim 1, wherein (c) and (d) incombination comprise: (i) processing the spectrum of measurements tocompute the total energy in band and the standard deviation of the powerspectral density in band for the plurality of frequency bands; (ii)discarding frequency bands in which the total energy in band is lessthan a threshold; (iii) processing the total energy in band and a centerfrequency of the frequency band to compute a weighted energy in band;and (iv) computing a ratio of the weighted energy in band to thestandard deviation of the power spectral density in band for thefrequency bands not discarded in (ii).